Weak natural gas prices in the third quarter have so far moved Alberta Energy Co. Ltd. to escalate a maintenance program and reduce its produced gas volumes by about 50 MMcf/d. Dominion and Occidental Petroleum Corp. also reported their third quarter earnings last week, and like many of their peers, both had slight production declines.

The lower production trend is expected to expand this week, as independents Apache Corp. and Anadarko Petroleum Corp. both release their third quarter earnings. On Friday, Anadarko attempted to prepare investors for lower third quarter earnings and production results, which are expected on Wednesday, reporting it will record a non-cash, pre-tax charge of $827 million, or $483 million after-taxes ($1.81 per diluted share), in the quarter also because of low natural gas prices and unusually high differentials for heavy oil at the end of the quarter.

Meanwhile, at Burlington Resources Inc., total third quarter production actually increased 2%, but analysts noted last week that the Houston-based producer probably will be an exception to the rule for the next three quarters — as producers face the likelihood of lower earnings until energy prices rebound.

However, instead of curtailing production, which EOG Resources and Newfield Exploration recently said they plan to do (see NGI, Oct. 1), some analysts expect to see more maintenance activities like those begun at AEC, where drilling and exploration activity will slow but work will continue on other activities. As the exploration and production (E&P) companies have begun reporting their third quarter earnings, many are highlighting strong fuel sales and opportunities they plan into 2002 — when natural gas and oil prices may rise.

Irene Haas of Sanders Morris Harris in Houston said that Burlington, which may have had higher production figures but lost money in the third quarter, will do “okay” in light of the Canadian Hunter acquisition (see NGI, Oct. 15). However, in general, she said, Burlington’s production rise will be an exception. Into the fourth quarter and through the second quarter of 2002, Haas said, “I would expect to see a lot of E&Ps lower their production expectations.”

Haas said that the lowered expectations are a function of price, and for the foreseeable future, the “gas prices will be soft [and]…oil prices are uncertain.” She said with that uncertainty, E&Ps are more likely to spend less money until they can get a “better footing.” Haas said she thought there would be more announcements about production curtailments. She expects those announcements to come during third quarter earnings releases or into the first quarter. National Fuel said it probably would curtail production in the first quarter (see related story).

“Ultimately, the companies have to make a profit,” Haas said, and with the softening market, it will be important for them to ensure their companies are on solid ground instead of spending money on exploitation and drilling. However, for those companies “who have cash and a good balance sheet,” Haas expects to hear about additional acquisitions and consolidations. “This is a better time to buy, and I foresee more” from the majors, she said.

Tom Driscoll of Lehman Brothers disagreed with Haas that companies may begin to shut in production. Driscoll expects, however, to see a slowdown on the drilling side.”Prices have to rebound before you see any upswing on the drilling,” he said. With the volatility of gas prices, Driscoll said it’s difficult for any of the E&Ps to get a handle on the “forward curve,” so they move resources to maintenance activities until the prices meet their expectations.

John Olson of Sanders, Morris Harris noted that “history seems to be repeating itself.” The Houston-based analyst said that overall, he sees gas production at “plus or minus 1% for the industry” overall. “We had production boosted much of the first half of the year by natural gas liquids (NGL) plant rejection (not taking ethanes out of the gas stream) and that boosted production, unusually in the first quarter especially.”

However, Olson said that will not be the case in the third quarter because margins on NGL processing have come back recently. Calling the cycle “the treadmill effect,” Olson said that while new gas well completions are adding “some plush production,” they are being offset by the natural decline curves of some of the older fields and some field blowdowns.

“We will continue to see some offsetting trend,” Olson said. Companies expected to have good production comparisons include Mitchell Energy and Development Corp., which is being acquired by Devon Energy Corp. (see NGI, Aug. 20). Mitchell, said Olson, is typically the best of the bunch.

Looking forward, Olson warned that “an air pocket has been created by the overkill in gas storage by the big energy marketers, all of whom have been playing the price contango. That has been very apparent for the last six months, and indeed, still refuses to go away. As a result, what we have had is a market that has been driven more by accounting justifications than by reality.

“This market in terms of sheer supply/demand fundamentals is probably not going to get back on its feet until April 1 presuming normal weather,” Olson added. “The trends for the fourth quarter should basically be mostly negative simply because of the fact that you see El Paso Energy having 65 rigs out there running, and that may head towards 20-25.” He added that signs of this scaling back are beginning to show throughout the industry.

For Calgary-based AEC, production may have been down, but its third quarter saw record oil and gas sales of 368,000 boe/d, a 21% increase from the third quarter a year ago. Third quarter daily natural gas sales were up 27% to 1.4 Bcf, while oil and liquid sales were up 13% to nearly 136,000 bbl/d over last year. The midstream division also saw a 68% increase in operating cash flow.

“Our strong operating performance was not able to overcome the dramatic slump in natural gas prices and the retreat in oil prices, but our operational progress has never been better,” said CEO Gwyn Morgan. He noted that the first nine months of the year were “highlighted by discoveries, acquisitions and dispositions” that strengthened AEC’s future. “We are in an outstanding position to capitalize on the expected return of the natural gas story.”

Morgan said that the “quality of AEC’s upstream assets is evidenced” by its growth in oil and gas sales, and has targeted a sales growth rate “exceeding 35% from existing assets to a forecast of more than 500,000 boe/d by 2004.” AEC also injected about 70 MMcf/d into storage in the third quarter and expects to enter the winter heating season with about 22 Bcf in storage.

However, things come into focus when looking at the earnings figures — and AEC is no exception. For the third quarter, AEC’s cash from operations was C$436 million, or C$2.66 per share diluted, a 23% decrease from the third quarter of 2000. Net earnings were down 16% to C$230 million.

Third quarter earnings included a gain of C$100 million after tax on the sale of the Jonah Gas Gathering Co., net of the cost of closing out purchased gas contracts. Houston-based Texas Eastern Products Pipeline Co. LLC finalized its acquisition of the Jonah Gas Gathering Co. from Green River Pipeline LLC and McMurry Oil Co., both wholly owned subsidiaries of AEC earlier this month (see NGI, Oct. 8).

At Burlington, a conference call with the investment community on Thursday also highlighted its increased production in the third quarter and its ramping up for the coming year — when it expects to see 3-8% growth coming from its acquisition of Canadian Hunter. That deal is expected to close as early as Nov. 20. However, executives downplayed the reduced earnings report.

Burlington reported net income of $73 million for the quarter, or $0.36 per diluted share, compared to net income of $200 million or $0.93 per share for the same period a year ago. Total production, however, increased 2% to 2,326 MMcfe/d, or by 8% per diluted share. “The production increase was more than offset by significantly lower commodity prices,” Burlington stated in its income release.

Burlington CFO Steven J. Shapiro said during the teleconference on earnings that “volumes in the third quarter were in line” with forecasts, and said that the company had been “very active…despite the lower time for drilling.” He said the company offset some drilling programs to focus on nonrestrictive access areas and the fourth quarter would see a “ramping up in drilling speed.”

Shapiro cautioned that despite maintaining a “fair level of high activity,” the company would “continue to monitor the conditions” on whether to reduce drilling into next year. For now, he said, the company is focusing on “executing a busy winter schedule of drilling in Canada,” bringing Canadian Hunter into the fold by the end of the year and beginning planned divestitures in Gulf of Mexico assets and non-core onshore assets.” He would no elaborate on the divestitures, but said the company was selling “some of its higher cost operating things.”

In what Dominion CEO Thomas Capps termed a “difficult business environment,” for the third quarter, the Richmond, VA-based company produced 50.2 Bcf domestically, marking a slight decline from the 50.9 Bcf it reported during the second quarter of 2001, and a large decline from third quarter 2000, when it reported production of 56.3 Bcf.

Overall, Dominion revealed that its unaudited consolidated earnings on the quarter increased by $74 million over the same quarter in 2000, posting earnings of $344 million ($1.37 per share), compared to operating earnings of $270 million ($1.13 per share) for the same period in 2000. Dominion Exploration & Production contributed $78 million ($0.31 per share) in the quarter, up from $66 million ($0.28 per share) in the prior-year period, with most of the increase attributed to higher realized gas and oil prices, partially offset by higher operating expenses and lower production.

For the rest of this year and into 2002, Dominion reaffirmed its earnings targets of $4.15 or better in 2001 and $4.85 to $4.90 in 2002, excluding its acquisition of Louis Dreyfus Natural Gas (see NGI, Sept. 17). Dominion said the acquisition is expected to close by year-end and add about $0.05 per share to 2002 earnings.

Domestic gas production at Occidental also declined in the quarter, dropping to 602 MMcf, down from 687 MMcf/d a year earlier. Los Angeles-based Occidental reported a 10% increase in net income, after special items, posting $444 million ($1.19 per share), compared with $402 million ($1.09 per share) for the same period of 2000. The quarter included the sale of non-strategic assets, including its interest in the Tangguh LNG project in Indonesia and the sale of the entity that leased a pipeline in Texas to Occidental’s former MidCon subsidiary.

In its precursor to the third quarter announcement expected on Wednesday, Anadarko, currently the largest U.S. independent, said that excluding its non-cash pre-tax charge of $827 million, it expects recurring third-quarter results to be above Wall Street analysts’ recent consensus estimates. The charge reflects a $464 million after-tax impairment of the carrying value of oil and gas properties in Western Canada and a $19 million after-tax impairment of the carrying value of assets in Argentina and Brazil, the company said.

Said Anadarko CEO Robert J. Allison, “We continue to be enthusiastic about our business in Canada, and this write-down will not have a significant effect on our operations there.”

Anadarko said the charge will have no significant effect on its capital structure. The company’s total capitalization at the end of the second quarter, before the write-down, was 37% debt and 63% equity. Following the write-down, the company said debt is expected to be about 39% of total capitalization. “While this impairment will give Anadarko a significant loss in the third quarter, the resulting reduction of future-period expenses for depreciation, depletion and amortization will increase net income by approximately $50 million annually for the next several years at current production rates,” the company said in a written statement.

The impairment, said Anadarko, is the result of applying what is commonly known as a “ceiling test” under rules prescribed by the U.S. Securities and Exchange Commission (SEC) for exploration and production companies such as Anadarko that use the “full-cost” accounting method. A company using the ceiling test compares the net capitalized costs of its oil and gas properties on a country-by-country basis against the present value (assuming a 10% discount rate) of future net cash flows from those reserves, generally using commodity prices on the last day of the quarter, held flat for the life of the reserves, Anadarko added. If the net capitalized costs exceed this valuation, the company must record a non-cash write-down equal to the difference.

“The price deck the SEC requires us to use in this ceiling test isn’t representative of today’s market environment, but that’s the rule, and we have to follow it,” Allison said. “Furthermore, those low prices do not represent what the market believes the reserves are worth. This write-down effectively values our Canadian proved reserves at less than 60 cents per Mcfe, which is about half what companies have recently paid for Canadian reserves.”

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